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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-Q (Mark One) þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934  OR o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 
  TRANSCONTINENTAL GAS PIPE LINE CORPORATION  Delaware
(State or other jurisdiction of
incorporation or organization)
    
    74-1079400
(I.R.S. Employer
Identification No.)
 2800 Post Oak Boulevard
P. O. Box 1396
Houston, Texas
(Address of principal executive offices)
    
    77251
(Zip Code)
 Registrants telephone number, including area code (713) 215-2000 None
(Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yesþ  Noo Indicate by check mark whether the registrant is an accelerated filer (as defined in
Exchange Act Rule 12b-2). YesoNoþ The number of shares of Common Stock, par value $1.00 per share, outstanding as of
April 30, 2005 was 100. REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS H (1)(a) AND (b) OF FORM
10-Q AND IS THEREFORE FILING THIS FORM 10-Q WITH THE REDUCED DISCLOSURE FORMAT.




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION
INDEX PagePART I. FINANCIAL INFORMATION:Item 1. Financial Statements -Condensed Consolidated Statement of Income for the three months ended March 31, 2005 and 2004.
    
    
    2Condensed Consolidated Balance Sheet as of March 31, 2005 and December 31, 2004
    
    
    3Condensed Consolidated Statement of Cash Flows for the three months ended March 31, 2005 and 2004
    
    
    5Notes to Condensed Consolidated Financial Statements
    
    
    6Item 2. Managements Narrative Analysis of the Results of Operations
    
    
    15Item 4. Controls and Procedures
    
    
    19PART II. OTHER INFORMATION
    
    
    20Item 1. Legal Proceedings.
    
    
    20Item 6. Exhibits
    
    
    20Section 302 Certification of Principal Executive OfficerSection 302 Certification of Principal Finanical OfficerSection 906 Certification of Principal Executive Officer and Principal Finanical Officer
  Certain matters discussed in this report, excluding historical information, include
forward-looking statements  statements that discuss our expected future results based on current
and pending business operations. We make these forward-looking statements in reliance on the safe
harbor protections provided under the Private Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such as anticipates, believes,
expects, planned, scheduled, could, continues, estimates, forecasts, might,
potential, projects or similar expressions. Although we believe these forward-looking
statements are based on reasonable assumptions, statements made regarding future results are
subject to a number of assumptions, uncertainties and risks that may cause future results to be
materially different from the results stated or implied in this document. Additional information
about issues that could cause actual results to differ materially from forward-looking statements
is contained in our 2004 Annual Report on Form 10-K. 1




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PART 1  FINANCIAL INFORMATION 
 ITEM 1. Financial Statements. TRANSCONTINENTAL GAS PIPE LINE CORPORATION 
 CONDENSED CONSOLIDATED STATEMENT OF INCOME   Three Months EndedMarch 31,2005
    
    
    2004Operating Revenues:Natural gas sales
    
    $
    120,506
    
    
    $
    123,874Natural gas transportation
    
    
    195,258
    
    
    
    206,926Natural gas storage
    
    
    30,874
    
    
    
    31,560Other
    
    
    2,307
    
    
    
    2,478Total operating revenues
    
    
    348,945
    
    
    
    364,838Operating Costs and Expenses:Cost of natural gas sales
    
    
    120,506
    
    
    
    122,325Cost of natural gas transportation
    
    
    3,296
    
    
    
    11,240Operation and maintenance
    
    
    47,357
    
    
    
    49,397Administrative and general
    
    
    24,962
    
    
    
    31,226Depreciation and amortization
    
    
    48,921
    
    
    
    47,469Taxes - other than income taxes
    
    
    10,088
    
    
    
    12,749Other (income) expense, net
    
    
    221
    
    
    
    (13
    )Total operating costs and expenses
    
    
    255,351
    
    
    
    274,393Operating Income
    
    
    93,594
    
    
    
    90,445Other (Income) and Other Deductions:Interest expense
    
    
    20,120
    
    
    
    22,166Interest income  affiliates
    
    
    (2,662
    )
    
    
    (1,371
    )Allowance for equity and borrowed funds used during construction (AFUDC)
    
    
    (1,691
    )
    
    
    (1,518
    )Equity in earnings of unconsolidated affiliates
    
    
    (1,647
    )
    
    
    (1,676
    )Miscellaneous other (income) deductions, net
    
    
    (818
    )
    
    
    (745
    )Total other (income) and other deductions
    
    
    13,302
    
    
    
    16,856Income before Income Taxes
    
    
    80,292
    
    
    
    73,589Provision for Income Taxes
    
    
    30,225
    
    
    
    28,241Net Income
    
    $
    50,067
    
    
    $
    45,348
 See accompanying notes. 2




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION 
 CONDENSED CONSOLIDATED BALANCE SHEET   March 31,
    
    
    December 31,2005
    
    
    2004ASSETSCurrent Assets:Cash
    
    $
    190
    
    
    $
    176Receivables:Affiliates
    
    
    2,357
    
    
    
    1,947Advances to affiliates
    
    
    92,740
    
    
    
    302,765Others less allowance of $909 ($1,724 in 2004)
    
    
    130,710
    
    
    
    112,387Transportation and exchange gas receivables
    
    
    12,575
    
    
    
    5,810Inventories
    
    
    90,418
    
    
    
    105,379Deferred income taxes
    
    
    20,176
    
    
    
    20,494Other
    
    
    20,914
    
    
    
    13,543Total current assets
    
    
    370,080
    
    
    
    562,501Investments, at cost plus equity in undistributed earnings
    
    
    43,224
    
    
    
    43,592Property, Plant and Equipment:Natural gas transmission plant
    
    
    5,894,643
    
    
    
    5,879,814Less-Accumulated depreciation and amortization
    
    
    1,630,153
    
    
    
    1,594,177Total property, plant and equipment, net
    
    
    4,264,490
    
    
    
    4,285,637Other Assets
    
    
    237,175
    
    
    
    232,147Total assets
    
    $
    4,914,969
    
    
    $
    5,123,877
 See accompanying notes. 3




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION CONDENSED CONSOLIDATED BALANCE SHEET (Continued)
(Thousands of Dollars)
(Unaudited) March 31,
    
    
    December 31,2005
    
    
    2004LIABILITIES AND STOCKHOLDERS EQUITYCurrent Liabilities:Payables:Affiliates
    
    $
    71,103
    
    
    $
    43,063Other
    
    
    56,088
    
    
    
    66,195Transportation and exchange gas payables
    
    
    18,438
    
    
    
    23,131Accrued liabilities
    
    
    115,302
    
    
    
    164,528Reserve for rate refunds
    
    
    3,912
    
    
    
    8,919Current maturities of long-term debt
    
    
    
    
    
    
    199,991Total current liabilities
    
    
    264,843
    
    
    
    505,827Long-Term Debt
    
    
    1,000,043
    
    
    
    999,858Other Long-Term Liabilities:Deferred income taxes
    
    
    962,118
    
    
    
    962,987Other
    
    
    157,072
    
    
    
    154,714Total other long-term liabilities
    
    
    1,119,190
    
    
    
    1,117,701Contingent liabilities and commitments (Note 2)Common Stockholders Equity:Common stock $1.00 par value:100 shares authorized, issued and outstanding
    
    
    
    
    
    
    Premium on capital stock and other paid-in capital
    
    
    1,652,430
    
    
    
    1,652,430Retained earnings
    
    
    879,048
    
    
    
    848,981Accumulated other comprehensive loss
    
    
    (585
    )
    
    
    (920
    )Total common stockholders equity
    
    
    2,530,893
    
    
    
    2,500,491Total liabilities and stockholders equity
    
    $
    4,914,969
    
    
    $
    5,123,877
 See accompanying notes. 4




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION 
 CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS   Three Months EndedMarch 31,2005
    
    
    2004Cash flows from operating activities:Net income
    
    $
    50,067
    
    
    $
    45,348Adjustments to reconcile net income to net cash provided
by (used in) operating activities:Depreciation and amortization
    
    
    49,448
    
    
    
    47,991Deferred income taxes
    
    
    2,883
    
    
    
    14,688Allowance for equity funds used during construction (Equity AFUDC)
    
    
    (1,029
    )
    
    
    (1,077
    )Changes in operating assets and liabilities:Receivables
    
    
    (18,733
    )
    
    
    18,831Transportation and exchange gas receivables
    
    
    (6,765
    )
    
    
    90Inventories
    
    
    14,961
    
    
    
    1,155Payables
    
    
    42,511
    
    
    
    (314
    )Transportation and exchange gas payables
    
    
    (4,693
    )
    
    
    672Accrued liabilities
    
    
    (49,481
    )
    
    
    (25,724
    )Reserve for rate refunds
    
    
    (5,007
    )
    
    
    (5,228
    )Other, net
    
    
    (8,753
    )
    
    
    11,434Net cash provided by operating activities
    
    
    65,409
    
    
    
    107,866Cash flows from financing activities:Retirement of long-term debt
    
    
    (200,000
    )
    
    
    Debt issue costs
    
    
    (234
    )
    
    
    Change in cash overdrafts
    
    
    (12,126
    )
    
    
    (13,568
    )Common stock dividends paid
    
    
    (20,000
    )
    
    
    Net cash used in financing activities
    
    
    (232,360
    )
    
    
    (13,568
    )Cash flows from investing activities:Property, plant and equipment:Additions, net of equity AFUDC
    
    
    (35,728
    )
    
    
    (25,079
    )Changes in accounts payable
    
    
    (4,852
    )
    
    
    (9,514
    )Advances to affiliates, net
    
    
    210,025
    
    
    
    (59,145
    )Other, net
    
    
    (2,480
    )
    
    
    (557
    )Net cash provided by (used in) investing activities
    
    
    166,965
    
    
    
    (94,295
    )Net increase in cash
    
    
    14
    
    
    
    3Cash at beginning of period
    
    
    176
    
    
    
    300Cash at end of period
    
    $
    190
    
    
    $
    303
 See accompanying notes. 5




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION 
 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION Transcontinental Gas Pipe Line Corporation (Transco) is a wholly-owned subsidiary of Williams
Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc.
(Williams). In this report, Transco (which includes Transcontinental Gas Pipe Line Corporation and unless
the context otherwise requires, all of our subsidiaries) is at times referred to in the first
person as we us or our. The condensed consolidated financial statements include our accounts and the accounts of our
majority-owned subsidiaries. Companies in which we and our subsidiaries own 20 percent to 50
percent of the voting common stock or otherwise exercise significant influence over operating and
financial policies of the company are accounted for under the equity method. The condensed consolidated financial statements have been prepared from our books and records.
Certain information and footnote disclosures normally included in financial statements prepared in
accordance with accounting principles generally accepted in the United States have been condensed
or omitted. The condensed unaudited consolidated financial statements include all adjustments both
normal recurring and others which, in the opinion of our management, are necessary to present
fairly our financial position at March 31, 2005, and results of operations for the three months
ended March 31, 2005 and 2004, and cash flows for the three months ended March 31, 2005 and 2004.
These condensed consolidated financial statements should be read in conjunction with the
consolidated financial statements and the notes thereto included in our 2004 Annual Report on Form
10-K. As a participant in Williams cash management program, we have advances to and from Williams.
The advances are represented by demand notes. The interest rate on intercompany demand notes is
based upon the weighted average cost of Williams debt outstanding at the end of each quarter.
Prior to April 29, 2004, the advances were made to and from our parent company, WGP. Through an agency agreement, Williams Power Company (WPC), an affiliate of ours, manages all
jurisdictional merchant gas sales for us, receives all margins associated with such business and,
as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas
sales. Consequently, our merchant gas sales service has no impact on our operating income or
results of operations. Most of these sales are made under Firm Sales (FS) agreements which give
customers the option to purchase daily quantities of gas from us at market-responsive prices in
exchange for a demand charge payment. Pursuant to the terms of an agreement with the FERC which
resolved a prior investigation, we terminated our remaining FS agreements effective April 1, 2005.
WPC continues to act as our agent to manage our other jurisdictional merchant gas sales. The preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires management to make estimates and assumptions that affect the
amounts reported in the consolidated financial statements and accompanying notes. Actual results
could differ from those estimates. Estimates and assumptions which, in the opinion of management,
are significant to the underlying 6




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amounts included in the financial statements and for which it would be reasonably possible
that future events or information could change those estimates include: 1) revenues subject to
refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4)
impairment assessments of long-lived assets; 5) deferred and other income taxes; 6) depreciation;
7) pensions and other post-employment benefits; and 8) asset retirement obligations. Comprehensive income for the three months ended March 31, 2005 and 2004 respectively, are as
follows (in thousands): Three MonthsEnded March 31,2005
    
    
    2004Net income
    
    $
    50,067
    
    
    $
    45,348Equity interest in
unrealized gain/(loss) on
interest rate hedge, net of
tax
    
    
    335
    
    
    
    (195
    )Total comprehensive income
    
    $
    50,402
    
    
    $
    45,153
 Recent accounting standardsIn December 2004, the Financial Accounting Standards Board
(FASB) issued revised Statement of Financial Accounting Standards (SFAS) No. 123, Share-Based
Payment. The statement requires that compensation costs for all share based awards to employees
be recognized in the financial statements at fair value. The statement, as issued by the FASB, was
to be effective as of the beginning of the first interim or annual reporting period that begins
after June 15, 2005. However, on April 15, 2005, the Securities and Exchange Commission (SEC)
adopted a new rule which amends the compliance dates for SFAS No. 123. The rule allows
implementation of the statement at the beginning of the next fiscal year that begins after June 15,
2005. We intend to adopt the revised statement as of January 1, 2006. In March 2005, the FASB issued Interpretation (FIN) No. 47, Accounting for Conditional Asset
Retirement Obligations-an interpretation of FASB Statement No. 143. The statement clarifies that
the term conditional asset retirement obligation, as used in SFAS No. 143, Accounting for Asset
Retirement Obligations, refers to a legal obligation to perform as asset retirement activity in
which the timing and (or) method of settlement are conditional on a future event that may or may
not be within the control of the entity. This interpretation also clarifies when an entity would
have sufficient information to reasonably estimate the fair value of an asset retirement
obligation. The effective date of this interpretation is no later than the end of the fiscal year
ending after December 15, 2005. We are assessing the impact of this interpretation on our financial
statements. In March 2005, the FASB issued FSP FIN 46(R)-5, Implicit Variable Interests under the FASB
Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities. The
Staff Position (FSP) is effective for the interim reporting period beginning April 1, 2005. The
FSP states that a reporting enterprise must consider implicit variable interests when applying the
provisions of FIN 46(R). We are currently evaluating the FSP to determine whether it has an impact
on our consolidated financial position and results of operations. 7




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2. CONTINGENT LIABILITIES AND COMMITMENTS Rate and Regulatory Matters General rate case (Docket No. RP01-245)On March 1, 2001, we submitted to the Federal Energy
Regulatory Commission (FERC) a general rate filing principally designed to recover costs associated
with an increase in rate base resulting from additional plant, an increase in rate of return and
related taxes, and an increase in operation and maintenance expenses. In July 2002, the FERC approved a Stipulation and Agreement (Settlement) which resolved all
cost of service, throughput and throughput mix issues in this rate case proceeding with the
exception of one cost of service issue related to the valuation of certain right-of-way access for
the installation of a fiber optic system by a then Transco affiliate, the resolution of which is to
be applied prospectively. The other issues not resolved by the Settlement include various cost
allocation, rate design and tariff matters. On December 3, 2002, an Administrative Law Judge (ALJ) issued his initial decision on the
issues not resolved by the Settlement. In the initial decision, the ALJ determined, among other
things, that (1) our existing treatment of the arrangement with our former affiliate relating to
right of way is just and reasonable, (2) our proposal to roll-in the costs of the Cherokee, Pocono
and SunBelt projects is unjust and unreasonable, and (3) our recovery of the costs of the Mobile
Bay expansion project on a rolled-in basis is unjust and unreasonable. As to the Mobile Bay issue,
the ALJ determined that we had the burden of establishing that roll-in of that project is just and
reasonable, but did not address the issue of any potential refunds. Our current rates are based on
the roll-in of the Mobile Bay expansion project. On March 26, 2004, the FERC issued an order that affirmed, in part, and reversed, in part, the
ALJs initial decision on the issues not resolved by the Settlement. On the issues discussed above,
the FERC affirmed the ALJs determination that our existing treatment of the arrangement with our
former affiliate relating to right of way is just and reasonable and our proposal to roll-in the
costs of the Cherokee, Pocono and SunBelt projects is unjust and unreasonable, but reversed the
ALJs rejection of our proposal to recover the costs of the Mobile Bay expansion project on a
rolled-in basis and found that we had shown that our proposed rolled-in rates are just and
reasonable. The FERC also affirmed the ALJs determination that we must separate our Emergency
Eminence Withdrawal service from our Rate Schedule FT service and offer the Emergency Eminence
Withdrawal service under a separate rate schedule, thereby permitting shippers to decide whether to
take that service. Currently, the costs of the Emergency Eminence Withdrawal service is included as
part of our Rate Schedule FT service for those shippers that can access the Eminence Storage Field.
Under the FERCs decision, we would be at risk for those costs to the extent that shippers did not
elect to subscribe to all of the separately offered service. Pursuant to the Settlement, this
change, if upheld, would be implemented on a prospective basis. On April 26, 2004, several parties,
including Transco, filed requests for rehearing of the FERCs March 26, 2004 order. Gathering facilities spin-down order (Docket Nos. CP96-206-000 and CP96-207-000)In 1996, we
filed an application with the FERC for an order authorizing the abandonment of certain facilities
located onshore and offshore in Texas, Louisiana and Mississippi by conveyance to an affiliate,
Williams Gas Processing - Gulf Coast Company (Gas Processing). The net book value of these
facilities at March 31, 2005, was approximately $326 million. Concurrently, Gas Processing filed a
petition for declaratory order requesting a determination that its gathering services and rates be
exempt from FERC regulation under the NGA. The FERC issued an order dismissing our application and
Gas Processings petition for declaratory order and in 2001, the FERC issued an order that denied
our request for rehearing. Certain parties, including 8




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Transco, filed in the United States Court of Appeals for the District of Columbia Circuit
(D.C. Circuit Court) petitions for review of the FERCs orders and in June 2003, those petitions
were denied. Several parties petitioned the United States Supreme Court for review of the D.C.
Circuit Courts opinion, and on January 12, 2004, the Court denied those petitions. While the proceedings related to the 1996 application were pending, we filed with the FERC the
applications described below seeking authorization to abandon portions of the facilities included
in the 1996 application. North Padre Island/Central Texas Systems Spin-down Proceeding (Docket Nos. CP01-32 and
CP01-34)In 2000, we filed an application with the FERC seeking authorization to abandon certain of
our offshore Texas facilities by conveyance to Gas Processing. Gas Processing filed a
contemporaneous request that the FERC declare that the facilities sought to be abandoned would be
considered nonjurisdictional gathering facilities upon transfer to Gas Processing. The FERC
approved the abandonment and the non-jurisdictional treatment of all of these facilities. Effective
December 2001, we transferred to Gas Processing the North Padre Island facilities through a
non-cash dividend of $3.3 million, which represents the net book value of the facilities as of that
date. Parties filed petitions for review of the FERCs orders to the D.C. Circuit Court which were
consolidated with the appeals of the FERCs orders in CP96-206 and CP96-207, discussed above, and
which were denied by the D.C. Circuit Court in its opinion issued in June, 2003. In 2001, Shell
Offshore, Inc. filed a complaint at the FERC against Gas Processing, Williams Field Services
Company (WFS) and us alleging concerted actions by these affiliates frustrated the FERCs
regulation of us. The alleged actions are related to offers of gathering service by WFS and its
subsidiaries with respect to the North Padre Island facilities. In 2002, the FERC issued an order
reasserting jurisdiction over that portion of the North Padre Island facilities previously
transferred to WFS. The FERC also determined a gathering rate for service on these facilities,
which is to be collected by us. Transco, Gas Processing and WFS each sought rehearing of the FERCs
order, and in May 2003, the FERC denied those requests for rehearing. Transco, Gas Processing and
WFS filed petitions for review of the FERCs orders with the D.C. Circuit Court and on July 13,
2004, the court granted the petitions, vacating the FERCs orders and remanding the case to the
FERC for further proceedings not inconsistent with the courts opinion. On February 15, 2005, the
FERC issued an order in response to the D.C. Circuit remand. In that order, the FERC determined
that, based on the record and the courts decision, there is not a sufficient basis to reassert
Natural Gas Act of 1938 (NGA) jurisdiction or to assert Outer Continental Shelf Lands Act
jurisdiction over the gathering rates and service on the North Padre Island facilities.
Accordingly, the FERC reversed the Initial Decision, dismissed the complaint filed by Shell, and
directed us to remove the North Padre Island gathering rate and rate schedule from our tariff. On
March 7, 2005, Shell filed a request for rehearing of the FERCs February 15, 2005 order. With regard to the approval of the spin-down of the Central Texas facilities, a Transco
customer filed a complaint with the FERC in Docket No. RP02-309 seeking the revocation of the
FERCs spin-down approval. In September 2002, the FERC issued an order requiring that, upon
transfer of the Central Texas facilities, we acquire capacity on the transferred facilities and
provide service to the existing customer under the original terms and conditions of service. Our
request for rehearing was denied in May 2003. In that order, the FERC also required that we notify
the FERC of Transcos plans with regard to the transfer of the Central Texas facilities to Gas
Processing. We replied that due to the numerous outstanding issues affecting the transfer of those
facilities, we could not at that time predict the timing for the implementation of the transfer of
the Central Texas facilities. Transco and the customer each also filed a request for rehearing of
the FERCs May 2003 order. On May 6, 2004, the FERC issued an order on rehearing effectively
granting the customers request for rehearing. On June 7, 2004, we filed a request for rehearing of
the May 6, 2004 order, which the FERC denied on July 6, 2004. On July 14, 2004, we filed a petition
for review of the FERCs 9




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orders with the D.C. Circuit Court. After we filed our initial brief, the FERC filed a motion
for a voluntary remand of the record to permit the FERC to further consider the issues raised and
to hold the proceedings in abeyance pending issuance of FERC orders on the matter. On February 11,
2005, the D.C. Circuit Court granted FERCs motion and remanded the record of this proceeding to
the FERC. At March 31, 2005, the net book value of these facilities was $64 million including the
Williams purchase price allocation pushed down to Transco. North High Island/West Cameron Systems and Central Louisiana System Spin-down ProceedingsIn
2001 the FERC issued orders authorizing us to spin down only a portion of these systems to Gas
Processing. All legal challenges of these FERC orders have been exhausted and while we have not yet
transferred any of the facilities authorized for spin down to our gas processing affiliate, we
continue to evaluate the option of doing so. On May 6, 2004, the FERC issued an order relating to
the Central Louisiana system spin-down proceeding in which the FERC required Transco and Gas
Processing to show cause, due to developments in another proceeding, why certain of the Central
Louisiana facilities previously found to be gathering should not be classified as jurisdictional
transmission facilities. We filed our response to the show cause order on July 6, 2004, arguing
that the FERC should not alter its conclusion that the facilities serve a gathering function. On
April 19, 2005, the FERC issued an order reversing its earlier finding and found that the
facilities in question are jurisdictional transmission facilities. We intend to seek rehearing of
the FERCs April 19, 2005 order. The net book value, at the application dates in 2001, of the North High Island/West Cameron
and Central Louisiana facilities included in these two applications was approximately $65 million
including the Williams purchase price allocation pushed down to Transco. South Texas Pipeline Facilities Abandonment ProceedingIn May 2003, the FERC denied our
request to abandon the South Texas pipeline facilities by sale to a third party. On June 25, 2003,
Transco and the third party purchaser announced that they had agreed to terminate the purchase and
sale agreement for the facilities. On July 6, 2004, we executed another agreement to sell the South
Texas pipeline facilities to a third party, but on March 24, 2005, the FERC denied our application
for authorization to effectuate the sale. No party requested rehearing of the FERCs March 24, 2005
order denying the sale, so that order is now final. The net book value of the South Texas pipeline
facilities as of March 31, 2005 was approximately $29 million, including the Williams purchase
price allocation pushed down to Transco. 1999 Fuel Tracker (Docket No. TM99-6-29)On March 1, 1999, we made our annual filing pursuant
to our FERC Gas Tariff to recalculate the fuel retention percentages applicable to our
transportation and storage rate schedules, to be effective April 1, 1999. Included in the filing
were two adjustments that increased the estimated gas required for operations in prior periods by
approximately 8 billion cubic feet. Certain parties objected to the inclusion of those adjustments
and the FERC accepted the filing to be effective April 1, 1999, subject to refund and to further
FERC action. In subsequent orders, the FERC initially disallowed most of the adjustments, but later
reconsidered that decision and allowed us to make the adjustments, with the requirement we collect
the adjustments over a seven-year period. Although several of our customers filed for rehearing of
the FERCs decision to allow us to recover the adjustments, the FERC denied the request for
rehearing, and an appeal of the FERCs decision was filed but later dismissed. In the second
quarter of 2001, we recorded a $15 million reduction in the cost of natural gas transportation and
reduced the related interest expense by $3 million to reflect the regulatory approval to recover
the cost of gas required for operations in prior periods. 10




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The FERC then issued orders in which it addressed our proposed method for recovering the
permitted adjustments. The FERC determined that rather than collecting the revenue (including
interest) represented by the adjustments, we should collect only the actual volumes comprising the
adjustments. In the third quarter of 2002, as a result of the FERCs determination, we recorded $3
million of interest expense that had been previously reduced in the second quarter of 2001. Certain
customers filed requests for rehearing of the FERCs decision, the FERC denied those requests and
several parties filed a joint petition for review in the D.C. Circuit Court of the FERCs order. In
accordance with the FERCs order, on January 21, 2004 we distributed refunds and assessed
surcharges to our customers for the period April 1, 1999 through March 31, 2003. On March 10, 2004,
we assessed further surcharges to our customers covering the period April 1, 2003 through January
31, 2004. We implemented the revised fuel retention factors resulting from application of the
FERCs order on a prospective basis beginning February 1, 2004. Following the filing of the
petitioners initial brief in their appeal of the FERCs orders, the FERC filed a motion with the
D.C. Circuit Court requesting that the court remand the record of the proceeding to the FERC to
permit the FERC to further consider the issues raised by the petitioners and to hold the appeal in
abeyance pending issuance of any further FERC order on this matter. On November 29, 2004, the D.C.
Circuit Court issued an order granting the FERCs motion. Pursuant to a settlement agreement
between Transco and petitioners, on April 5, 2005, the petitioners filed a motion with the FERC
stating that they had determined that they no longer wished to contest the FERCs orders that were
under review in the appeal, and requested that the FERC issue an order terminating the remand
proceeding. Once that order becomes final, the petitioners stated that they will file with the
D.C. Circuit Court to dismiss the appeal. OtherWilliams, including Transco, responded to a subpoena from the Commodities Futures
Trading Commission (CFTC) and inquiries from the FERC related to investigations involving natural
gas storage inventory issues. We own and operate natural gas storage facilities. On August 30,
2004, the CFTC announced that it had concluded its investigation. The FERC inquiries relate to the
sharing of non-public data concerning inventory levels and the potential uses of such data in
natural gas trading. The FERC investigation is continuing and Williams is engaged in discussions
with FERC staff that are likely to result in an ultimate disposition of this matter through a
settlement that would include some amount of penalty and refund, the financial effect of which
ultimately will be borne by an affiliate. Legal Proceedings. Royalty claims and litigationIn connection with our renegotiations with producers to resolve
take-or-pay and other contract claims and to amend gas purchase contracts, we entered into certain
settlements which may require that we indemnify producers for claims for additional royalties
resulting from such settlements. Through our agent WPC, we continue to purchase gas under contracts
which extend, in some cases, through the life of the associated gas reserves. Certain of these
contracts contain royalty indemnification provisions, which have no carrying value. We have been
made aware of demands on producers for additional royalties and such producers may receive other

demands which could result in claims against us pursuant to royalty indemnification provisions.
Indemnification for royalties will depend on, among other things, the specific lease provisions
between the producer and the lessor and the terms of the agreement between the producer and us.
Consequently, the potential maximum future payments under such indemnification provisions cannot be
determined. As a result of these settlements, we have been sued by certain producers seeking
indemnification. We are currently a defendant in one such lawsuit. Freeport-McMoRan, Inc., filed a
lawsuit against us in the 19th Judicial District Court in East Baton Rouge, Louisiana in
which it asserted damages, including interest 11




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calculated through March 31, 2005, of approximately $10 million. The case was tried in 2003
and resulted in a judgment favorable to us, which Freeport-McMoRan is appealing. In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg,
an individual, had filed claims in the United States District Court for the District of Colorado
under the False Claims Act against Williams and certain of its wholly-owned subsidiaries including
us. Mr. Grynberg has also filed claims against approximately 300 other energy companies and alleges
that the defendants violated the False Claims Act in connection with the measurement, royalty
valuation and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties
allegedly not paid to the federal government, treble damages, a civil penalty, attorneys fees, and
costs. In April 1999, the DOJ declined to intervene in any of the Grynberg qui tam cases, including
the action filed against the Williams entities in the United States District Court for the District
of Colorado. In October 1999, the Panel on Multi-District Litigation transferred all of the
Grynberg qui tam cases, including those filed against Williams, to the United States District Court
for the District of Wyoming for pre-trial purposes. In October 2002, the court granted a motion to
dismiss Grynbergs royalty valuation claims. Grynbergs measurement claims remain pending against
Williams, including us, and the other defendants, although the defendants have filed a number of
motions to dismiss these claims on jurisdictional grounds. Oral argument on these motions occurred
on March 17 and 18, 2005, and we expect a decision in the second quarter of 2005. Environmental Matters We are subject to extensive federal, state and local environmental laws and regulations which
affect our operations related to the construction and operation of pipeline facilities. Appropriate
governmental authorities enforce these laws and regulations with a variety of civil and criminal
enforcement measures, including monetary penalties, assessment and remediation requirements and
injunctions as to future compliance. Our use and disposal of hazardous materials are subject to the
requirements of the federal Toxic Substances Control Act (TSCA), the federal Resource Conservation
and Recovery Act (RCRA) and comparable state statutes. The Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA), also known as Superfund, imposes liability, without
regard to fault or the legality of the original act, for release of a hazardous substance into
the environment. Because these laws and regulations change from time to time, practices that have
been acceptable to the industry and to the regulators have to be changed and assessment and
monitoring have to be undertaken to determine whether those practices have damaged the environment
and whether remediation is required. Since 1989, we have had studies underway to test some of our
facilities for the presence of toxic and hazardous substances to determine to what extent, if any,
remediation may be necessary. We have responded to data requests from the U.S. Environmental
Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our
sites. On the basis of the findings to date, we estimate that over the next three years
environmental assessment and remediation costs under TSCA, RCRA, CERCLA and comparable state
statutes will total approximately $21 million to $25 million, measured on an undiscounted basis.
This estimate depends upon a number of assumptions concerning the scope of remediation that will be
required at certain locations and the cost of the remedial measures. We are conducting
environmental assessments and implementing a variety of remedial measures that may result in
increases or decreases in the total estimated costs. At March 31, 2005, Transco had a balance of
approximately $23 million for these estimated costs recorded in current liabilities ($4 million)
and other long-term liabilities ($19 million) in the accompanying Condensed Consolidated Balance
Sheet. 12




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We consider prudently incurred environmental assessment and remediation costs and costs
associated with compliance with environmental standards to be recoverable through rates. To date,
we have been permitted recovery of environmental costs, and it is our intent to continue seeking
recovery of such costs, through future rate filings. Therefore, these estimated costs of
environmental assessment and remediation have also been recorded as regulatory assets in current
assets and other assets in the accompanying Condensed Consolidated Balance Sheet. We have used lubricating oils containing polychlorinated biphenyls (PCBs) and, although the
use of such oils was discontinued in the 1970s, we have discovered residual PCB contamination in
equipment and soils at certain gas compressor station sites. We have worked closely with the EPA
and state regulatory authorities regarding PCB issues, and we have a program to assess and
remediate such conditions where they exist. In addition, we commenced negotiations with certain
environmental authorities and other programs concerning investigative and remedial actions relative
to potential mercury contamination at certain gas metering sites. All such costs are included in
the $21 million to $25 million range discussed above. We have been identified as a potentially responsible party (PRP) at various Superfund and
state waste disposal sites. Based on present volumetric estimates and other factors, our estimated
aggregate exposure for remediation of these sites is less than $500,000. The estimated remediation
costs for all of these sites have been included in the environmental reserve discussed above.
Liability under CERCLA (and applicable state law) can be joint and several with other PRPs.
Although volumetric allocation is a factor in assessing liability, it is not necessarily
determinative; thus, the ultimate liability could be substantially greater than the amounts
described above. We are also subject to the federal Clean Air Act and to the federal Clean Air Act Amendments
of 1990 (1990 Amendments), which added significantly to the existing requirements established by
the federal Clean Air Act. The 1990 Amendments required that the EPA issue new regulations, mainly
related to stationary sources, air toxics, ozone non-attainment areas and acid rain. During the
last few years we have been installing new emission control devices required for new or modified
facilities in areas designated as non-attainment by EPA. We operate some of our facilities in areas
of the country currently designated as non-attainment with the one-hour ozone standard. In April
2004, EPA designated eight-hour ozone non-attainment areas. We also operate facilities in areas of
the country now designated as non-attainment with the eight-hour ozone standard. Pursuant to
non-attainment area requirements of the 1990 Amendments, and proposed EPA rules designed to
mitigate the migration of ground-level ozone (NOx) in 22 eastern states, we are planning
installation of air pollution controls on existing sources at certain facilities in order to reduce
NOx emissions. We anticipate that additional facilities may be subject to increased controls within
five years. For many of these facilities, we are developing more cost effective and innovative
compressor engine control designs. Due to the developing nature of federal and state emission
regulations, it is not possible to precisely determine the ultimate emission control costs. In
March 2004 and June 2004, the EPA promulgated additional regulations regarding hazardous air
pollutants; these regulations may impose controls in addition to the controls described above. The
emission control additions required to comply with current federal Clean Air Act requirements, the
1990 Amendments, the hazardous air pollutant regulations, and the individual state implementation
plans for NOx reductions are estimated to include costs in the range of $110 million to $125
million subsequent to 2004. EPAs recent designation of new non-attainment areas will result in new
federal and state regulatory action that may impact our operations. As a result, the cost of
additions to property, plant and equipment is expected to increase. We are unable at this time to
estimate with any certainty the cost of additions that may be required to meet new regulations,
although it is believed that some of those costs are included in the ranges discussed above.
Management considers costs associated 13




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with compliance with the environmental laws and regulations described above to be prudent
costs incurred in the ordinary course of business and, therefore, recoverable through our rates. Safety Matters Pipeline Integrity RegulationsWe have developed an Integrity Management Plan that meets the
United States Department of Transportation Office of Pipeline Safety final rule pursuant to the
requirements of the Pipeline Safety Improvement Act of 2002. In meeting the Integrity Regulations,
we have identified the high consequence areas, including a baseline assessment and periodic
reassessments to be completed within specified timeframes. Currently, we estimate that the cost to
perform required assessments and repairs will be between $275 million and $325 million over the
remaining assessment period of 2005 through 2012. Management considers the costs associated with
compliance with the rule to be prudent costs incurred in the ordinary course of business and,
therefore, recoverable through our rates. Summary Litigation, arbitration, regulatory matters, environmental matters and safety matters are
subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the
possibility of a material adverse impact on the results of operations in the period in which the
ruling occurs. Management, including internal counsel, currently believes that the ultimate
resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued,
insurance coverage, recovery from customers or other indemnification arrangements, will not have a
materially adverse effect upon our future financial position. Other Commitments Commitments for constructionWe have commitments for construction and acquisition of property,
plant and equipment of approximately $68 million at March 31, 2005. 3. DEBT AND FINANCING ARRANGEMENTS Revolving Credit and Letter of Credit Facilities Under Williams $1.275 billion secured revolving credit facility, letters of credit totaling
$455 million, none of which are associated with us, have been issued by the participating
institutions and no revolving credit loans were outstanding at March 31, 2005. Retirements In January 2005, we retired $200 million of 6 1/8% Notes. The notes, which were issued in
January 1998, were retired at the scheduled maturity date with no gain or loss recorded. 14




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4. STOCK-BASED COMPENSATION Employee stock-based awards are accounted for under Accounting Principles Board (APB) Opinion
No. 25, Accounting for Stock Issued to Employees and related interpretations. Williams
fixed-plan common stock options generally do not result in compensation expense because the
exercise price of the stock options equals the market price of the underlying stock on the date of
grant. The following table illustrates the effect on net income for the three months ended March
31, 2005 and 2004 if we had applied the fair value, estimated using the Black-Scholes pricing
model, recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation. Three monthsEnded March 31,2005
    
    
    2004(Thousands of Dollars)Net income, as reported
    
    $
    50,067
    
    
    $
    45,348Add: Stock-based employee
compensation included in the
Condensed Consolidated Statement of
Income, net of related tax effects
    
    
    97
    
    
    
    72Deduct: Stock-based employee
compensation expense determined
under fair value based method for all
awards, net of related tax effects
    
    
    (400
    )
    
    
    (650
    )Pro forma net income
    
    $
    49,764
    
    
    $
    44,770
 Since compensation expense for stock options is recognized over the future years vesting
period for pro forma disclosure purposes and additional awards are generally made each year, pro
forma amounts may not be representative of future years amounts. 
 ITEM 2. Managements Narrative Analysis of Results of Operations. General The following discussion should be read in conjunction with the consolidated financial
statements, notes and managements narrative analysis contained in Items 7 and 8 of Transcos 2004
Annual Report on Form 10-K and with the condensed consolidated financial statements and notes
contained in this report. RESULTS OF OPERATIONS Operating Income and Net Income Our operating income for the three months ended March 31, 2005 was $93.6 million compared to
operating income of $90.4 million for the three months ended March 31, 2004. Net income for the
three months ended March 31, 2005 was $50.1 million compared to $45.3 million for the three months
ended March 31, 2004. The higher operating income of $3.2 million was due to reductions in
operating costs and expenses exceeding the reductions in operating revenues as discussed below. The
increase in net income of $4.8 million was attributable to the increased operating income and a
$3.6 million reduction of other income and other deductions as discussed below. 15




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Transportation Revenues Our operating revenues related to transportation services for the three months ended March 31,
2005 were $195.3 million, compared to $206.9 million for the three months ended March 31, 2004. The
lower transportation revenues of $11.6 million were primarily due to a decrease of reimbursable
costs that are included in operating expenses and recovered in our rates. As shown in the table below, our total market-area deliveries for the three months ended March
31, 2005 decreased 4.2 trillion British Thermal Units (TBtu) (0.9%) when compared to the same
period in 2004. The decreased deliveries are primarily the result of lower market demand due to
fewer heating degree days compared to the same period last year. Our production area deliveries for
the three months ended March 31, 2005 decreased 7.1 TBtu (10.5%) when compared to the same period
in 2004.This is primarily due to decreased requests for deliveries to production area
interconnects. Three monthsEnded March 31,Transco System Deliveries (TBtu)
    
    2005
    
    
    2004Market-area deliveries:Long-haul transportation
    
    
    209.8
    
    
    
    213.9Market-area transportation
    
    
    267.5
    
    
    
    267.6Total market-area deliveries
    
    
    477.3
    
    
    
    481.5Production-area transportation
    
    
    60.4
    
    
    
    67.5Total system deliveries
    
    
    537.7
    
    
    
    549.0Average Daily Transportation Volumes (Tbtu)
    
    
    6.0
    
    
    
    6.0Average Daily Firm Reserved Capacity (Tbtu)
    
    
    6.9
    
    
    
    6.8
 Our facilities are divided into eight rate zones. Five are located in the production area
and three are located in the market area. Long-haul transportation is gas that is received in one
of the production-area zones and delivered in a market-area zone. Market-area transportation is gas
that is both received and delivered within market-area zones. Production-area transportation is gas
that is both received and delivered within production-area zones. Sales Revenues We make jurisdictional merchant gas sales to customers pursuant to a blanket sales certificate
issued by the FERC, with most of those sales being made under Firm Sales (FS) agreements which give
customers the option to purchase daily quantities of gas from us at market-responsive prices in
exchange for a demand charge payment. Pursuant to the terms of an agreement with the FERC which
resolved a prior investigation, we terminated our remaining FS agreements effective April 1, 2005.
We continue to have the ability to make other jurisdictional merchant gas sales under our blanket
sales certificate. 16




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Through an agency agreement, WPC manages our jurisdictional merchant gas sales, which excludes
our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by
WPC remain in our name, as do the corresponding sales of such purchased gas. Therefore, we continue
to record natural gas sales revenues and the related accounts receivable and cost of natural gas
sales and the related accounts payable for the jurisdictional merchant sales that are managed by
WPC. WPC receives all margins associated with jurisdictional merchant gas sales business and, as
our agent, assumes all market and credit risk associated with our jurisdictional merchant gas
sales. Consequently, our merchant gas sales service has no impact on our operating income or
results of operations and, therefore, the termination of the FS agreements in April 2005, will have
no impact on our operating income or results of operations. In addition to our merchant gas sales, we also have cash out sales, which settle gas
imbalances with shippers. The cash out sales have no impact on our operating income or results of
operations. Operating revenues related to our sales services were $120.5 million for the three months
ended March 31, 2005, compared to $123.9 million for the same period in 2004. The decrease was
primarily due to a lower volume of merchant sales during the first three months of 2005 compared to
the same period in 2004. Three monthsEnded March 31,Gas Sales Volumes (TBtu)
    
    2005
    
    
    2004Long-term sales
    
    
    7.8
    
    
    
    11.5Short-term sales
    
    
    2.7
    
    
    
    2.2Total gas sales
    
    
    10.5
    
    
    
    13.7
 Storage Revenues Our operating revenues related to storage services of $30.9 million for the three months ended
March 31, 2005 were comparable to the revenues of $31.6 million for the same period in 2004. Other Revenues Our other operating revenues of $2.3 million for the three months ended March 31, 2005 were
comparable to the revenues of $2.5 million for the same period in 2004. Operating Costs and Expenses Excluding the cost of natural gas sales of $120.5 million for the three months ended March 31,
2005 and $122.3 million for the comparable period in 2004, our operating expenses for the three
months ended March 31, 2005, were approximately $17.2 million lower than the comparable period in
2004. This decrease was primarily attributable to lower cost of natural gas transportation,
operation and maintenance expense, administrative and general expenses, and taxes other than income
taxes. The lower cost of natural gas transportation of $7.9 million resulted from a decrease of
$5.4 million in 2005 of reimbursable costs that are recovered in our rates and lower fuel expense
of $2.6 million due to the benefit of pricing differentials in 2005 related to volumes of gas used
in operations. The decrease in operation and maintenance expense in 2005 of $2.0 million is due
primarily to lower operating costs associated with the gathering facilities. The decrease in
administrative and general expense of $6.3 million is mostly due to lower reimbursable costs 17




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associated with post-retirement costs other than pensions of $2.2 million and Gas Research
Institute charges of $2.2 million. The $2.7 million decrease in taxes other than income taxes was mostly due to
the reduction of various state franchise tax liabilities in 2005 due to the settlement of prior
year audits. Other Income and Other Deductions Other income and other deductions for the three months ended March 31, 2005 resulted in lower
net expense of $3.6 million compared to the same period in 2004. This was primarily due to a $2.6
million decrease in interest expense resulting from the retirement of $200 million of 6 1/8% notes
in January 2005. Capital Expenditures As shown in the table below, our capital expenditures for the three months ended March 31,
2005 were $40.6 million, compared to $34.6 million for the three months ended March 31, 2004. Three monthsEnded March 31,Capital Expenditures
    
    2005
    
    
    2004(In Millions)Market-area projects
    
    $
    2.6
    
    
    $
    9.6Supply-area projects
    
    
    3.7
    
    
    
    4.5Maintenance of existing facilities and other projects
    
    
    34.3
    
    
    
    20.5Total capital expenditures
    
    $
    40.6
    
    
    $
    34.6
 Our capital expenditures estimate for 2005 and future capital projects are discussed in
our 2004 Annual Report on Form 10-K. The following describes those projects and any new capital
projects proposed by us. Central New Jersey Expansion ProjectThe Central New Jersey Expansion Project will involve an
expansion of our existing natural gas transmission system in Zone 6 from the Station 210 pooling
point to locations along our Trenton-Woodbury Line. The project will create 105,000 dekatherms per
day (dt/d) of new firm transportation capacity, which has been fully subscribed by one shipper for
a twenty-year primary term. The project facilities will include approximately 3.5 miles of pipeline
loop at a total estimated capital cost of $13 million. We filed an application for FERC
authorization of the project on August 11, 2004, which the FERC approved by order issued on
February 10, 2005. One party filed a request for rehearing of that order, but on April 13, 2005,
the FERC denied the rehearing request. The target in-service date for the project is November 1,
2005. Leidy to Long Island Expansion ProjectThe Leidy to Long Island Expansion Project will involve
an expansion of our existing natural gas transmission system in Zone 6 from the Leidy Hub in
Pennsylvania to Long Island, New York. The project will provide 100,000 dt/d of firm
transportation capacity, which has been fully subscribed by one shipper for a twenty-year primary
term. The project facilities will include pipeline looping in Pennsylvania and looping and a
natural gas compressor facility in New Jersey. The estimated capital cost of the project is $103
million. We expect that nearly three-quarters of the project expenditures will occur in 2007. The
FERC has granted our request to initiate a pre-application environmental review, soliciting early
input from citizens, governmental entities, and other interest parties to identify and address
potential sitting issues. We expect to file a formal application with the FERC in September 2005.
The target in-service date for the project is November 1, 2007. 18




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ITEM 4. Controls and Procedures. An evaluation of the effectiveness of the design and operation of our disclosure controls and
procedures (as defined in Rule 13a-15(e) and 15(d)-(e) of the Securities Exchange Act) (Disclosure
Controls) was performed as of the end of the period covered by this report. This evaluation was
performed under the supervision and with the participation of our management, including our Senior
Vice President and Vice President and Treasurer. Based upon that evaluation, our Senior Vice
President and Vice President and Treasurer concluded that these Disclosure Controls are effective
at a reasonable assurance level. Our management, including our Senior Vice President and Vice President and Treasurer, does not
expect that our Disclosure Controls or our internal controls over financial reporting (Internal
Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and
operated, can provide only reasonable, not absolute, assurance that the objectives of the control
system are met. Further, the design of a control system must reflect the fact that there are
resource constraints, and the benefits of controls must be considered relative to their costs.
Because of the inherent limitations in all control systems, no evaluation of controls can provide
absolute assurance that all control issues and instances of fraud, if any, within the company have
been detected. These inherent limitations include the realities that judgments in decision-making
can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally,
controls can be circumvented by the individual acts of some persons, by collusion of two or more
people, or by management override of the control. The design of any system of controls also is
based in part upon certain assumptions about the likelihood of future events, and there can be no
assurance that any design will succeed in achieving its stated goals under all potential future
conditions. Because of the inherent limitations in a cost-effective control system, misstatements
due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and
Internal Controls and make modifications as necessary; our intent in this regard is that the
Disclosure Controls and the Internal Controls will be modified as systems change and conditions
warrant. There has been no material change that occurred during the
first fiscal quarter in our Internal Controls over financial reporting. 19




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PART II  OTHER INFORMATION 
 ITEMS 1. LEGAL PROCEEDINGS. See discussion in Note 2 of the Notes to Condensed Consolidated Financial Statements
included herein. 
 ITEM 6. EXHIBITS The following instruments are included as exhibits to this report.
Those exhibits below incorporated by reference herein are indicated as such by
the information supplied in the parenthetical thereafter. If no parenthetical
appears after an exhibit, copies of the instrument have been included herewith. (31) Section 302 Certifications    1
    Certification of Principal Executive Officer pursuant to
Rules 13a-14(a) and 15d-14(a) promulgated under the
Securities Exchange Act of 1934, as amended, and Item
601(b)(31) of Regulation S-K, as adopted pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.  2
    Certification of Principal Financial Officer pursuant to
Rules 13a-14(a) and 15d-14(a) promulgated under the
Securities Exchange Act of 1934, as amended, and Item
601(b)(31) of Regulation S-K, as adopted pursuant to Section
302 of the Sarbanes-Oxley Act of 2002. (32) Section 906 Certification  
    Certification of Principal Executive Officer and
Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 20




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SIGNATURE Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized. TRANSCONTINENTAL GAS PIPE LINE
CORPORATION (Registrant)Dated:  May 6, 2005
    By /s/ Jeffrey P. HeinrichsJeffrey P. HeinrichsController
(Principal Accounting Officer) 21